|Publication number||US7839148 B2|
|Application number||US 11/396,494|
|Publication date||Nov 23, 2010|
|Priority date||Apr 3, 2006|
|Also published as||CA2581437A1, CA2581437C, DE102007015727A1, DE102007015727B4, US20070229082|
|Publication number||11396494, 396494, US 7839148 B2, US 7839148B2, US-B2-7839148, US7839148 B2, US7839148B2|
|Inventors||Imran Vehra, James J. Freeman, Christopher A. Golla, Randal T. Beste, Michael S. Bittar|
|Original Assignee||Halliburton Energy Services, Inc.|
|Export Citation||BiBTeX, EndNote, RefMan|
|Patent Citations (11), Non-Patent Citations (2), Referenced by (11), Classifications (8), Legal Events (3)|
|External Links: USPTO, USPTO Assignment, Espacenet|
1. Field of the Invention
Various embodiments of the invention are directed to logging tools, such as wireline tools and logging tools used while drilling. More particularly, various embodiments of the invention are directed to calibration of sensors to compensate for tool drift which may be associated with temperature and/or age of the tool.
2. Description of the Related Art
Modern drilling operations demand a great quantity of information relating to the parameters and conditions encountered downhole. Such information typically includes characteristics of the earth formations traversed by the wellbore, as well as information regarding the wellbore itself.
The collection of information relating to conditions downhole, which is commonly referred to as “logging,” may be performed by several methods. In wireline logging, a probe or “sonde” is suspended in the borehole by way of an armored cable (the wireline) after some or all of the well has been drilled. There are also tools that collect data during the drilling process. By collecting, processing and transmitting data to the surface real-time while drilling, the timeliness of measurement data of formation properties is improved and, consequently, the efficiency of drilling operations is increased. Tools that are used while drilling may be referred to as measurement-while-drilling (MWD) or logging-while-drilling tools (LWD). While there may be some distinction between MWD and LWD, the terms are often used interchangeably, and for purposes of this specification the term LWD will be used with the understanding that LWD may also refer to MWD operations.
A formation containing hydrocarbons has certain well known physical characteristics, such as resistivity (the inverse of conductivity) within a particular range. Measurements of resistivity are based on attenuation and phase shift of an electromagnetic signals propagating through the formation, and thus it is important to measure amplitude and phase shift accurately. Even small amounts of error are relatively significant given the small amplitude of signals detected at the receiver, which are often on the order of 10 nV. A long-standing phenomenon known as tool drift introduces errors in the measurement of attenuation and phase shift. In particular, as tool temperature varies, and as the tool ages, measurements of attenuation and phase shift of a received electromagnetic signal drift. The amount of drift varies from tool to tool, and can be substantial in deep wells where temperatures can exceed 150° Celsius.
In order to compensate for tool drift, related art logging tools may have their response as a function of temperature determined prior to deployment into the borehole. The downhole measurements are then compensated based on downhole temperature and the temperature response characteristics of the tool. However, determining the temperature response characteristics of a tool is a very time consuming and labor intensive process, and does not account for other drifts that may be encountered in a logging tool, such as the effect of aging. Other techniques may be to use a “compensated” logging tool having multiple symmetric receiver pairs. However, tools that use multiple symmetric receiver pairs require additional components and processing. Compensated tools tend to be longer, thus increasing cost. Moreover, “compensated” tool design requires a particular physical structure of the tool, and thus older tools may not be suited to be retrofitted with multiple symmetric receiver pairs.
For a more detailed description of the various embodiments of the present invention, reference will now be made to the accompanying drawings, wherein:
Certain terms are used throughout the following description and claims to refer to particular system components. This document does not intend to distinguish between components that differ in name but not function.
In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . ”. Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices and connections.
Drilling fluid is pumped from a pit 34 at the surface through the line 37, into the drill string 14 and to the drill bit 32. After flowing out through the face of the drill bit 32, the drilling fluid rises back to the surface through the annular area between the drillstring 14 and the borehole 18, where it is collected and returned to the pit 34 for filtering. The drilling fluid is used to lubricate and cool the drill bit 32 and to remove cuttings from the borehole 18.
A downhole controller 22 controls the operation of telemetry transmitter 28 and orchestrates the operation of downhole components. The controller processes data received from the logging tool 50 and/or sensors in the instrument sub 60 and produces encoded signals for transmission to the surface via the telemetry transmitter 28. The controller 22 may also make decisions based upon the processed data.
In accordance with embodiments of the invention, calibration of resistivity tool 200 may be made real time to account for tool drift. In particular, and in accordance with embodiments of the invention, a calibration signal is sent through the receiver components in the same way as an interrogating signal detected by the receiver coil(s), and in some situations the calibration signal is sent under approximately the same conditions as an interrogating signal is to be received. Instead of being supplied by the transmitter in the form of an electromagnetic wave, however, a calibration signal in accordance with embodiments of the invention is supplied by a signal generator proximate the receiver electronics. In accordance with some embodiments, determination of tool drift is made at a time close to when the formation resistivity is being measured (i.e. close enough in time that the conditions at the tool have not changed significantly).
Each receiver electronics 214, 216 and 218 are substantially identical, and thus the following discussion, while directed to receiver electronics 214, is equally applicable to each of the receiver electronics 214, 216 and 218. In particular, receiver electronics 214 comprises a transformer 224 that inductively couples received interrogating signals to the amplification, filtering and buffering circuits 234. The receiver electronics 214 also comprises a second transformer 222 that inductively couples the attenuator 226 (discussed more fully below) to both the receiver coil 206 and the amplification, filtering and buffering circuits 234. Although
Still referring to
Still referring to
In accordance with some embodiments of the invention, the calibration board 228 is located proximate the receiver electronics 214, 216 and 218. In this context, “proximate” means closer to the receiver electronics than to the transmitter coil. Because the distance is preferably relatively short, cross-talk and electrical interference of signals traveling on the harnesses is less severe and less likely. Moreover, and as illustrated, the transmitter electronics 227 and receiver electronics 214, 216 and 218 are preferably isolated on separate boards, further minimizing the potential for cross-talk. Further still, the presence of an attenuator on each receiver board 214, 216 and 218 allows a calibration signal of significantly greater signal strength to be transmitted between the calibration board 228 and the various receiver electronics 214, 216 and 218, thus improving the signal-to-noise ratio of a calibration signal received at each receiver electronics.
Another advantage of many embodiments of the invention is the use of a signal generator to generate the calibration signal, rather than use of the transmitter electronics. Using an independent system generating low level signals for the receiver input reduces the amount of power required to generate the calibration signal, extending battery life in LWD devices. Use of a separate signal generator for the calibration signal also allows placement of the signal generator proximate the receiver components, obviating the need for long wiring harnesses between the transmitter electronics and the receiver electronics.
In some embodiments, correcting for tool drift may be accomplished downhole, such as by the controller 22 (
One advantage of the various embodiments is the ability to test the receiver coils and harnesses. By including these components, a full picture is provided of possible sources of tool drift. Nonetheless, it is believed that drift is primarily associated with active electronics, and more specifically the active electronics associated with processing the signal detected at the receiver coils. The term “active” as used herein means a circuit that requires external power to operate, as opposed to “passive” circuits that do not require a supply of external to operate. The drift in phase and gain due to receiver antennae and harnesses remains relatively stable, due to the passive nature of these components. Thus, it is believed that the reduction or elimination of drift in the active receiver electronics results in the elimination of the majority of drift in the logging tool. In accordance with alternative embodiments of the invention, the calibration signal may be provided only through the active components.
While various embodiments of this invention have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit or teaching of this invention. For example, any number of transmitters or receivers may be used. Moreover, although it is expected that calibration of at least the active receiver electronics in a resistivity tool is the most cost effective and efficient approach to minimizing the effects of drift on resistivity tool measurements, it should be appreciated that the various embodiments may be applied to any component of a tool that is subject to tool drift. Further still, applying low strength calibration signal to receiver coil and electronics saves power over applying a large signal to transmitter, and thus the embodiments are particularly suited to a LWD environment; however, the various embodiments may also find application in a wireline tool. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims which follow, the scope of which shall include all equivalents of the subject matter of the claims.
|Cited Patent||Filing date||Publication date||Applicant||Title|
|US4736300 *||Sep 7, 1984||Apr 5, 1988||Western Atlas International, Inc.||Automatic gain control of formation measurements by varying induced current flow|
|US4876511||Oct 20, 1988||Oct 24, 1989||Schlumberger Technology Corporation||Method and apparatus for testing and calibrating an electromagnetic logging tool|
|US6208585||Jun 26, 1998||Mar 27, 2001||Halliburton Energy Services, Inc.||Acoustic LWD tool having receiver calibration capabilities|
|US6218842 *||Aug 4, 1999||Apr 17, 2001||Halliburton Energy Services, Inc.||Multi-frequency electromagnetic wave resistivity tool with improved calibration measurement|
|US20050088180 *||Nov 3, 2004||Apr 28, 2005||Flanagan William D.||Multiple transmitter and receiver well logging device with error calibration system|
|US20050168224||Nov 18, 2004||Aug 4, 2005||Halliburton Energy Services, Inc.||Receiver electronics proximate antenna|
|US20050189947 *||Mar 1, 2005||Sep 1, 2005||Pathfinder Energy Services, Inc.||Azimuthally focused electromagnetic measurement tool|
|US20060017443 *||Jul 15, 2005||Jan 26, 2006||Baker Hughes Incorporated||Deep reading propagation resistivity tool for determination of distance to a bed boundary with a transition zone|
|EP1206713B1||Aug 3, 2000||Mar 16, 2005||Halliburton Energy Services, Inc.||Multi-frequency electromagnetic wave resistivity tool with improved calibration measurement|
|WO2006012497A1||Jul 22, 2005||Feb 2, 2006||Baker Hughes Incorporated||Error correction and calibration of a deep reading propagation resistivity tool|
|WO2006052458A2||Oct 27, 2005||May 18, 2006||Ultima Labs, Inc.||Multiple transmitter and receiver well logging device with error calibration system|
|1||German Office Action dated Jan. 11, 2008 for German patent application No. 10 2007 015 727.6-24 and English translation.|
|2||Office Action dated Oct. 7, 2009 from British Patent Office for Application No. GB 0706456.1.|
|Citing Patent||Filing date||Publication date||Applicant||Title|
|US8749243||May 26, 2011||Jun 10, 2014||Halliburton Energy Services, Inc.||Real time determination of casing location and distance with tilted antenna measurement|
|US8844648||May 26, 2011||Sep 30, 2014||Halliburton Energy Services, Inc.||System and method for EM ranging in oil-based mud|
|US8890531||Jan 29, 2007||Nov 18, 2014||Halliburton Energy Services, Inc.||Systems and methods having pot core antennas for electromagnetic resistivity logging|
|US8890541||Aug 17, 2011||Nov 18, 2014||Baker Hughes Incorporated||Method and apparatus for calibrating deep-reading multi-component induction tools with minimal ground effects|
|US8917094||May 12, 2011||Dec 23, 2014||Halliburton Energy Services, Inc.||Method and apparatus for detecting deep conductive pipe|
|US8957683||Aug 11, 2009||Feb 17, 2015||Halliburton Energy Services, Inc.||High frequency dielectric measurement tool|
|US9115569||Jul 16, 2012||Aug 25, 2015||Halliburton Energy Services, Inc.||Real-time casing detection using tilted and crossed antenna measurement|
|US9157315||Aug 17, 2012||Oct 13, 2015||Halliburton Energy Services, Inc.||Antenna coupling component measurement tool having a rotating antenna configuration|
|US9310508||Jun 29, 2010||Apr 12, 2016||Halliburton Energy Services, Inc.||Method and apparatus for sensing elongated subterranean anomalies|
|US20090278543 *||Jan 29, 2007||Nov 12, 2009||Halliburton Energy Services, Inc.||Systems and Methods Having Radially Offset Antennas for Electromagnetic Resistivity Logging|
|US20100117655 *||Jan 19, 2010||May 13, 2010||Halliburton Energy Services, Inc.||Tool for Azimuthal Resistivity Measurement and Bed Boundary Detection|
|U.S. Classification||324/338, 324/339, 324/202|
|Cooperative Classification||G01V3/30, G01V13/00|
|European Classification||G01V13/00, G01V3/30|
|Apr 3, 2006||AS||Assignment|
Owner name: HALLIBURTON ENERGY SERVICES, INC., TEXAS
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:VEHRA, A. IMRAN;GOLLA, CHRISTOPHER A.;BESTE, C. RANDAL T.;AND OTHERS;REEL/FRAME:017757/0526;SIGNING DATES FROM 20060317 TO 20060329
|Jun 23, 2006||AS||Assignment|
Owner name: HALLIBURTON ENERGY SERVICES, INC., TEXAS
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:VEHRA, IMRAN;GOLLA, CHRISTOPHER A;BESTE, RANDAL T;AND OTHERS;REEL/FRAME:017837/0129;SIGNING DATES FROM 20060317 TO 20060329
|Apr 24, 2014||FPAY||Fee payment|
Year of fee payment: 4